Light gas separation from hydrocarbons for variable composition feed streams

ABSTRACT

The invention is a process and apparatus for separating the components of a multi-component gas stream comprising light and heavier volatility components with a variable composition. The process includes contacting the multi-component gas stream with a lean solvent in an absorber to produce a light component overhead stream and a rich solvent bottoms stream, flashing the rich solvent bottoms stream in at least a first, second and third reduced constant pressure of sequentially lower pressure wherein the released gas is compressed and a part is routed back to the absorber bottoms as stripping gas and a part is routed as a part of the heavier product stream. In this invention compressed vapor from the first or second reduced constant pressure rich solvent flash vessel is split by flow control between recycle routing to the absorber bottom stage as stripping gas and to the heavier product hydrocarbon stream, depending on the feed gas concentration of light component. The third and any additional flash vessels at sequentially lower pressure produce flash gas that is the remainder of the produced hydrocarbon product stream. The lean solvent remaining after the lowest pressure flash is routed back to the top of the absorber.

FIELD OF THE INVENTION

The invention relates to the field of chemical processing and, morespecifically, to the processing of hydrocarbon gas streams. Inparticular, a method and apparatus for separating the components of ahydrocarbon gas stream with variable composition is disclosed.

BACKGROUND OF THE INVENTION

Many hydrocarbon gases such as natural gas, coal mine and coal seamgases, landfill gases, refinery operation off-gases and hydroprocessingrecycle loop gases contain one or more light components that eithercontaminate the main gas or that are themselves more valuable if theycan be separated from the main gas stream. Such light gases includenitrogen and hydrogen. A number of economic considerations make itdesirable to separate these light gases from a hydrocarbon gas stream.

Absorption using a physical solvent to remove the heavier hydrocarboncomponents and therefore separate them from the light components can beemployed. This process is described in several patents, including U.S.Pat. Nos. 4,623,371, 4,680,042, 4,740,222, 4,832,718, 4,883,514,5,224,350, 5,325,672, 5,462,583, 5,551,972, 6,698,237 B2, 7,337,631 B2,7,442,847 B2, and 7,563,307 B2 along with U.S. patent application Ser.No. 12/082,976, all which are incorporated by reference herein in theirentirety. These patents describe absorption/flash regeneration systemsfor removal of light components such as nitrogen or hydrogen fromheavier components such as methane or ethylene. In most of thereferenced prior art, the feed gas and the lean solvent stream arechilled to between 0° F. (−17.7° C.) and −40° F. (−40° C.) to enhancerecovery of the heavier components and to reduce contamination of thelight component stream with heavier components, including solventcomponents. The absorber may operate at a wide range of pressures,typically 200 psig (13.8 barg) or higher. The last flash used to releasethe recovered heavier components from the rich solvent is operated atlow pressure to minimize the concentration of absorbed heaviercomponents in the lean solvent.

In these processes the heavier components are absorbed away from thelight components using a circulating physical solvent. Reducing thepressure of the rich solvent in one or more flash separators releasesthe heavier absorbed component and regenerates the solvent forrecirculation to the absorber. These patents address systems wherein thephysical solvent used is external, meaning a made up of component(s)added to the system (U.S. Pat. Nos. 4,623,371, 4,680,042, 4,740,222,4,832,718, 4,883,514) and also systems wherein the physical solvent usedis internally generated and is therefore composed of heaviestcomponent(s) in the feed gas (U.S. Pat. Nos. 5,462,583 and 5,551,972).Controlling the amount of light components in the rich solvent affectsthe recovery of the light component and the purity of the absorbed andreleased heavier component. In some applications, the vapor releasedfrom the first flash vessel is recycled to the bottom of the absorber asstripping gas, effectively reducing the amount of light component in theheavier component product released from the rich solvent in later flashvessels (U.S. Pat. Nos. 4,740,222, 4,832,718, 5,462,583, 5,551,972).Using this method, lowering the pressure of the first flash vessel willresult in a less light component in the heavy product. This first flashpressure must be lower when the amount of light component in the feed ishigher in order to maintain a similar heavier component purity. Theamount of light component absorbed and released with the heaviercomponent product can alternatively be controlled by recycle of heavycomponent product to the bottom of the absorber as stripping gas (U.S.Pat. No. 5,325,672), or with a reboiler on the absorber bottoms. Whenheavy component recycle is used, more recycle results in a purer heavycomponent, and a higher rate of recycle is required to maintain heavyproduct purity when the feed gas contains more light component.

A specification for the concentration of light component in the heavycomponent product can be controlled over a wide range of feed gascompositions using either the heavy product recycle method or the firstflash vapor recycle method. However, a design to accommodate a lowamount of light component in the feed, and also perform with a highconcentration results in design of each piece of equipment to handle theworst case load of the two operations required. An improvement to theprocess that results in improved flexibility to accommodate changes infeed composition and improved operability while minimizing or evenreducing associated system cost and complexity is needed.

SUMMARY OF THE INVENTION

An object of this invention is to improve operability and flexibility inan absorption separation process wherein the feed gas stream will varyin composition. Surprisingly, the inventive method developed to increaseoperability and flexibility has also resulted in a significant reductionin energy consumption and in total installed cost, with the powerrequired by the conventional process requiring 44% more installed gasrecompression horsepower.

A preferred embodiment of the invention is a process and apparatus forseparating the components of a multi-component gas stream comprisinglight and heavier volatility components with a variable composition. Theprocess includes contacting the multi-component gas stream with a leansolvent in an absorber to produce a light component overhead stream anda rich solvent bottoms stream, flashing the rich solvent bottoms streamin at least a first, a second, and a third reduced constant pressurestages of sequentially lower pressure wherein the released gas iscompressed by a compressor dedicated to the service and a part is routedback to the absorber bottoms as stripping gas and a part is routed as apart of the heavier product stream. In this embodiment compressed vaporfrom the first or second rich solvent flash vessel is split by flowcontrol between recycle routing to the absorber bottom stage asstripping gas and to the heavier product hydrocarbon stream, dependingon the feed gas concentration of light component. The third and anyadditional flash vessels at sequentially reduced constant pressureproduce flash gas that is the remainder of the produced hydrocarbonproduct stream. The lean solvent remaining after the lowest pressureflash is routed back to the top of the absorber.

Improved embodiments include the following items. When the flash gasrate from the first constant reduced pressure flash vessel is not enoughto produce required purity heavy hydrocarbon product gas, a part of thegas from the second constant reduced pressure flash vessel is alsorouted to the absorber bottoms stage. When only part of the flash gasfrom the first flash vessel is required for the product specification tobe met, the remainder of gas from the first flash is routed to thehydrocarbon product, and all of the gas from the second flash is alsorouted to the heavy hydrocarbon product. The flash gas from the firstflash vessel is compressed with the same compressor which is dedicatedto this service regardless of Where the compressed gas is routed. Thegas from the second constant reduced pressure flash vessel is alsocompressed in a compressor dedicated to the service regardless of wherethe compressed gas is routed.

The following are additional improved embodiments. The absorber mayoperate at a pressure from 200 to 3000 psia (13.8 to 207 bara), and theflash vessels may operate, each at a sequentially lower constantpressure, in a range of from 2800 psia (193 bara) for the highestpressure flash to 7 psia (0.48 bara) for the lowest pressure flashvessel. Each flash vessel typically has an operating pressure that isfrom 20 to 75% of the pressure of the preceding vessel. The temperaturein the absorber and the flash vessels may range from ambient down to 20°F. (−6.7° C.), or as low as −40° F. (−40° C.) when the system streamsare cooled with refrigeration. The rate of flash gas routed to theabsorber is controlled, and may be adjusted as needed to meet productpurity. Flash vessel pressures are constant, and constant pressure canbe maintained by control of flash gas routed to the hydrocarbon product.

The novel arrangement of this invention allows improved control of theprocess when there are variations in feed compositions, whilesurprisingly also reducing energy consumption. These objects, features,and advantages will be apparent in the following drawings, descriptionsand examples

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a conventional (comparative) process for separating thecomponents of a gas stream using lean oil absorption with flashregeneration of the solvent and with first flash vapor recycled to theabsorber as stripping gas.

FIG. 2 depicts a novel process for separating the components of a gasstream using lean oil absorption with flash recycle of stripping gas andflash regeneration of the solvent according to this invention whereinthe process includes the capability to split the compressed flash gaswith the first part of the gas being routed to the absorber bottom stagefor stripping and the second part being routed to the heavy hydrocarbonproduct, in order to improve control and operability when the feed gascomposition changes. An unexpected benefit is a significant reduction inenergy consumption and installed compressor horsepower.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

An object of this invention is to improve operability and flexibility inan absorption separation process wherein the feed gas stream will varyin composition. Surprisingly, the method developed to increaseoperability and flexibility has also resulted in a 31% decrease in gasrecompression installed horsepower and a 24% decrease in worst case gasrecompression operating horsepower as compared to a conventionalprocess.

The invention is a process and apparatus for separating the componentsof a multi-component gas stream comprising light and heavier volatilitycomponents with a variable composition. The process includes contactingthe multi-component gas stream with a lean solvent in an absorber toproduce a light component overhead stream and a rich solvent bottomsstream, flashing the rich solvent bottoms stream in at least threereduced constant pressure stages of sequentially lower pressure whereinthe released gas is compressed and a part is routed back to the absorberbottoms as stripping gas and a part is routed as a portion of theheavier product stream. In this embodiment compressed vapor from thefirst or second rich solvent flash vessel is split by flow controlbetween routing to the absorber bottom stage as stripping gas and to theheavier product hydrocarbon stream, depending on the feed gasconcentration of light component. The third and any additional flashvessels at sequentially lower pressure produce flash gas that is theremainder of the produced hydrocarbon product stream. The lean solventremaining after the lowest pressure flash is routed back to the top ofthe absorber.

In order to present the unique advantages and benefits of the newprocess, a review of conventional technology is provided.

Comparative Example 1

Conventional technology will be described through the use of a feed gascontaining the light component nitrogen, along with acid gases andhydrocarbons, wherein the feed composition of nitrogen is expected toincrease from an initial composition of 24% nitrogen to a finalcomposition of 54% nitrogen over a period of time. The producedhydrocarbon product is to be at the same pressure as the inlet gas,contain less than 2% molar nitrogen, and recover close to all of thehydrocarbon content of the feed gas. This is a realistic example for agas reservoir with a nitrogen cap added for pressure maintenance.

Referring to FIG. 1, the overall material balance and conditions for the24% nitrogen feed case are as follows:

TABLE 1 Heavy, Feed Gas - Light, N2 - Hydrocarbon- Excess Solvent -Stream 1 Stream 8 Stream 56 Stream 38 Pressure, psia (bara) 1067 (73.6) 1015 (70.0)  1067 (73.6)  141 (9.7)  Temperature, ° F. (° C.)  120(48.9) 110 (43.3)  124 (51.1)  125 (51.7) Flow, lb (kg) Mol/hr 5490(2490) 1291 (585.6) 4166 (1890) 32.5 (14.7) Composition, Mol Fraction N2.2400 .9725 .0148 .0000 CO2 .0056 .0004 .0072 .0000 H2S .0001 .0000.0002 .0000 C1 .6290 .0139 .8247 .0000 C2 .0866 .0083 .1116 .0001 C3.0207 .0028 .0264 .0030 iC4 .0029 .0004 .0035 .0102 nC4 .0063 .0010.0075 .0523 iC5 .0016 .0002 .0015 .0560 nC5 .0015 .0002 .0013 .0734 nC6.0030 .0002 .0012 .3381 nC7 .0017 .0000 .0002 .2404 nC8 .0007 .0000.0000 .1287 nC9 .0004 .0000 .0000 .0749 nC10 .0001 .0000 .0000 .0230

The feed gas 1 is cooled to −25° F. (−31.7° C.) in exchangers 2 and fedas stream 3 to an intermediate point in absorber 4. Cooling forexchangers 2 is provided by reheat of cold streams in exchangers 7, 54and 52 in parallel and lastly from a propane refrigerant chiller. Leansolvent stream 5 enters the top of the absorber, thereby contacting thefeed gas as it rises, and purified nitrogen-rich stream 6 exits the topat −24° F. (−31.1° C.), is reheated in exchanger 7 and leaves the systemas stream 8 at close to inlet pressure and temperature. Rich solvent inthe absorber below the inlet gas feed point is in contact with strippinggas 9, and the rich solvent leaves the bottom of the absorber as stream10 at 1021 psia (70.4 bara) and 7° F. (−14° C. Stream 10 is reduced inpressure by control valve 11, and enters flash vessel 13 as stream 12 at513 psia (35.4 bara) and −2° F. (−19° C.). Some of the inlet nitrogenwas absorbed into the rich solvent, along with the hydrocarbons. Thisflash vessel pressure allows release of enough of the absorbed nitrogenso that in the remaining sequential flashes the total released vaporwill meet a sales specification of <2% nitrogen content. The vapor fromthe first flash, stream 14, is compressed in compressor 15 and entersthe bottom of the absorber as stream 9. This not only provides strippinggas to the absorber, but also removes of the nitrogen from the richsolvent. The remaining flash vessels 39, 20, 25, and 30 operate at lowerpressures of 260, 190, 87 and 16 psia (17.9, 13.1, 6.9 and 1.1 bara)respectively. Control valves 18, 42, 23 and 28 provide both levelcontrol for the flash vessels and provide the pressure drop to releasemore of the absorbed hydrocarbons and the small amount of remainingnitrogen from the solvent. The vapor released from the flash vessels 39,20, 25, and 30 are streams 40, 21, 26 and 31 comprise the heavyhydrocarbon product stream after they have been reheated in exchangers52 and 54, and recompressed in multistage compressor 32, exiting as thehydrocarbon product stream 33. Stream 34 is the regenerated lean solventleaving the last flash vessel. This solvent enters pump 35, leaving asstream 36 at slightly above absorber operating pressure. Any excesssolvent is withdrawn as stream 38, and remaining lean solvent 57 is thenchilled in exchanger 37 using propane refrigeration to exit as stream 58at a temperature of −25° F. (−31.7° C.), and then 58 passing throughflow control valve 59, leaving as stream 5 and entering the absorber.The pressure of the last flash vessel 30 determines how pure the leansolvent is. The rate of solvent 5 controls the amount of hydrocarbonremaining in the nitrogen stream 8, and the pressure of the first flashvessel 13 controls the amount of nitrogen in the hydrocarbon product. Asthe inlet gas contains a significant amount of hydrocarbons heavier thanmethane, the solvent is made up of the heavier components of the solventthat do not vaporize in the flash vessels. This is referred to as aninternal solvent. Excess solvent is created continuously by the process,and is withdrawn as stream 38. It is not indicated in FIG. 1, but inthis example the excess solvent was further stabilized in a smallstripping tower with released overhead lighter components routed tocompressor 32, and the stabilized solvent bottoms product leaving thesystem, and indicated as stream 38 in the material balance above. Notethat air coolers are used on compressor discharges as required, and alsoon the solvent leaving the stabilizer, although these are not shown.Additional control points are also not indicated.

For this 24% nitrogen feed example, critical equipment loads are listedin the following table:

TABLE 2 Horsepower Flow, lb-moles/hr Equipment (KW) (kg-moles/hr)Compressor 32 5612 (4186) 4166 (1890) Compressor 15 1264 (943)  3835(1740) Refrigeration 3507 (2616) 3397 (1541) compressor (*) Pump 35 2537(1893) 12440 (9280) (*) Refrigeration compressor not shown in FIG. 1

Comparative Example 2

To complete review of conventional design performance, an alternativecase is evaluated. In the alternative scenario, the feed gas compositionmay increase to a maximum for 54% nitrogen, and in this example thisalternative feed, and all in between 24% and 54%, must be processed bythe same facility. The sales purity specification of <2% nitrogen isunchanged, and the inlet and outlet pressures and the feed gas flow rateare also unchanged. To accommodate this high nitrogen content feed, twochanges are made in the operation: the first flash vessel pressure isdecreased from 513 psia to 265 psia (35.4 to 18.3 bara) and the leansolvent rate is increased. The reduction in first flash pressureincreases the amount of stripping gas routed back to the bottom stage ofthe absorber so that the hydrocarbon product stream 33 will meet thepurity specification. The increase in solvent rate is required tomaintain purity of the light component stream 8. The operating pressurein the remaining flash vessels 39, 20, 25, and 30 is the same as inComparative Example 1. Solvent pump 35 horsepower increases inproportion to the 50% increase flow. The refrigeration requirement ofthe process increases by 25%. Critical equipment loads for the 24%nitrogen and the 54% nitrogen cases are presented in Table 3.

TABLE 3 24% Nitrogen Case 54% Nitrogen Case Flow, lb- Flow, lb-Horsepower moles/hr Horsepower moles/hr Equipment (KW) (kg-moles/hr)(KW) (kg-moles/hr) Compressor 32 5612 (4186) 4166 (1890) 4607 (3437)2474 (1122) Compressor 15 1264 (943)  3835 (1740) 4775 (3562) 6504(2950) Refrigeration 3507 (2616) 3397 (1541) 4408 (3288) 4266 (1935)compressor (*) Pump 35 2537 (1893) 12440 (9280)  3808 (2837) 16750(7598)  (*) Refrigeration compressor not shown in FIG. 1

Purity of the heavy hydrocarbon product stream and the light productnitrogen stream with 54% nitrogen are nearly identical to the productpurity in the 24% nitrogen feed gas case, so the objective of theprocess is met. However, the change in pressure of the first flashcreates practical problems. Absorber 4 pressure remains constant at 1021psia (70.4 bara) and the second flash vessel pressure remains constantat 264 psia (18.2 bara). With the first flash pressure change from 513psia (35.4 bara) in Comparative Example 1 to 265 psia (18.3 bara), levelcontrol valve 11 between the absorber and the first flash pressure has adifferential pressure change from 508 psi to 756 psi (35.0 to 52.1 bar).The differential pressure through level control valve 18 between thefirst and second flash vessels changes from 249 psi to 1 psi (17.2 to0.07 bar). There is almost no flow of vapor from the third flash vessel20. The third flash pressure must be reduced to allow adequate pressuredrop through valve 18 to maintain proper control of level in thevessels. The control of the flash vessel levels is more difficult in the54% case. Pressure in the flash vessels is controlled by the flowthrough the compressors, withdrawing the vapor from the flashes. Controlof the flash vessel pressure is also more difficult, as the flash vesselvapor compressor loads of flow and suction pressure are so differentfrom the 24% N2 case. The compression requirement changes affect theenergy consumption and the capital cost of the process. Compression forthe highest load case must be installed for the process to operate asrequired. Although the total of compression services 32 and 15 is 6,876horsepower (5129 KW) for the 24% nitrogen case and 9,382 (6999 KW) forthe 54% nitrogen case, the total actual installed horsepower would haveto be 10,387 (7749 KW).

Example 3

The process of the present invention is shown in FIG. 2.

The process of FIG. 2 was developed to address the problems of level andpressure control in the conventional process which can affectoperability. The objective is to have the flash vessels operate atconstant preset pressure even when the inlet gas composition changes.This would result in the level control valves between the flash vesselsalways having the same pressure drop available, Constant flash vesselpressure would also result in flash vessel vapor compressors alwayshaving the same suction pressure and compression ratio from suction todischarge. The method used to solve the control problems has had theunexpected and very beneficial result of significantly decreasing energyconsumption and capital cost.

The process of FIG. 2 will be described using the design feed range ofcompositions, conditions, and produced product specifications as wereused to describe the conventional technology, thereby allowingcomparison of results. Referring to FIG. 2, the overall material balanceand conditions for a 37% nitrogen feed case are as follows:

TABLE 4 Heavy, Excess Feed Gas - Light, N2 - Hydrocarbon- Solvent -Stream 1 Stream 8 Stream 56 Stream 38 Pressure, psia (bara) 1067 (73.6) 1015 (70.7) 1067 (73.6)  141 (9.7)  Temperature, ° F. ( C)  120 (48.9) 110 (43.3)  125 (51.7)  125 (51.7) Flow, lb-moles/hr 5490 (2490) 2074(941)  3397 (1541) 18.8 (8.53) (kg-moles/hr) Composition, Mol FractionN2 .3762 .9719 .0146 .0000 CO2 .0034 .0002 .0052 .0000 H2S .0001 .0000.0002 .0000 C1 .5246 .0176 .8372 .0000 C2 .0694 .0067 .1082 .0002 C3.0138 .0018 .0212 .0067 iC4 .0019 .0003 .0028 .0119 nC4 .0042 .0006.0061 .0480 iC5 .0010 .0002 .0013 .0393 nC5 .0010 .0002 .0013 .0577 11C6.0020 .0002 .0015 .3237 nC7 .0012 .0000 .0003 .2648 nC8 .0006 .0000.0000 .1446 nC9 .0003 .0000 .0000 .0781 nC10 .0001 .0000 .0000 .0253

The feed gas 1 is cooled to −25° F. (−31.7° C.) in exchangers 2 and fedas stream 3 to an intermediate point in absorber 4. Cooling forexchangers 2 is provided by reheat of cold streams in exchangers 7, 54and 52 in parallel and lastly from a propane refrigerant chiller. Leansolvent stream 5 enters the top of the absorber, thereby contacting thefeed gas as it rises, and purified nitrogen-rich stream 6 exits the topat −24° F. (−31.1° C.), is reheated in exchanger 7 and leaves the systemas stream 8 at close to inlet pressure and temperature. Rich solvent inthe absorber below the inlet gas feed point is in contact with strippinggas 9, and the rich solvent leaves the bottom of the absorber as stream10 at 1021 psia (70.4 bara) and 6° F. (−14.4° C.). Stream 10 is reducedin pressure by control valve 11, and enters flash vessel 13 as stream 12at a first constant reduced pressure of 513 psia (35.4 bara) and −1° F.(−18.3° C.). Some of the inlet nitrogen was absorbed into the richsolvent, along with the hydrocarbons. This flash vessel will releasepart of the nitrogen absorbed. The vapor from the first flash, stream14, is compressed in dedicated to service compressor 15 exiting asstream 60 and flows as stream 61 through valve 62, and as stream 63 ismixed with any flow in stream 48 to then enter the absorber bottom stageas stream 9. This not only provides stripping gas to the absorber, butalso removes of the nitrogen from the rich solvent. In this example,valve 65 is closed and there is no flow in streams 64 and 66. Theremaining flash vessels 39, 20, 25, and 30 operate at constant lowerpressures of 260, 190, 87 and 16 psia (17.9, 13.1, 6.0 and 1.1 bara)respectively. Control valves 18, 42, 23 and 28 provide both levelcontrol for the flash vessels and provide the pressure drop to releasemore of the absorbed hydrocarbons and the small amount of remainingnitrogen from the solvent. The vapor released from the second flashvessel, 39, is routed through dedicated compressor 44, exiting as stream45. A part of stream 45 flows as stream 46 through flow control valve47, exiting as stream 48 and joining stream 63 to enter the absorber assteam 9. The reminder of stream 45 flows though control valve 50 and isrouted to become part of the heavy hydrocarbon product stream 56. Inthis example about 48% of stream 45 is routed through valve 47 to theabsorber with a flow rate of 955 lb-moles/hr (433 kg-moles/fir). Thisvapor provides the additional stripping in the absorber and additionalnitrogen removal from vapor to produce a required purity of the producedhydrocarbon product. Control valve 50 can be used to control constantpressure in the second flash vessel. Control valve 65 would be used tocontrol pressure in the first flash vessel when the flow is split, withpart on flow control to the absorber and part on pressure control to thehydrocarbon product. The hydrocarbon product streams released from theflash vessels 20 and 25 are reheated in exchangers 52 and 54 againstinlet gas, and are compressed to product pressure by compressor 32, asis the vapor from the last flash vessel, stream 31. Stream 34 is theregenerated lean solvent leaving the last flash vessel. This solvententers pump 35, leaving as stream 36 at slightly above absorberoperating pressure. Any excess solvent is withdrawn as stream 38, andremaining lean solvent 57 is then chilled in exchanger 37 using propanerefrigeration to exit as stream 58 at a temperature of −25° F. (−31.7°C.), and then 58 passing through flow control valve 59, leaving asstream 5 and entering the absorber. The pressure of the last flashvessel 30 determines how pure the lean solvent is. The rate of solvent 5controls the amount of hydrocarbon remaining in the nitrogen stream 8.The total flow of recycled gas from flash vessels 13 and 39 controls theamount of nitrogen in the hydrocarbon product. As the inlet gas containsa significant amount of hydrocarbons heavier than methane, the solventis made up of the heavier components of the solvent that do not vaporizein the flash vessels. This is referred to as an internal solvent. Excesssolvent is created continuously by the process, and is withdrawn asstream 38. It is not indicated in FIG. 1, but in this example the excesssolvent was further stabilized in a small stripping tower with releasedoverhead lighter components routed to compressor 32, and the stabilizedsolvent bottoms product leaving the system, and indicated as stream 38in the material balance above. Note that air coolers are used oncompressor discharges as required, and also on the solvent leaving thestabilizer, although these are not shown. Additional control points arealso not indicated.

For this 37% nitrogen feed example, critical equipment loads are listedin the following table:

TABLE 5 Flow, lb- Duty, Horsepower moles/hr MMbtu/hr Equipment (KW)(kg-moles/hr) (MM kcal/hr) Compressor 32 4339 (3237) 2317 (1051)Compressor 44 1507 (1124) 2038 (924)  Compressor 15 1314 (980)  3948(1791) Refrigeration 3837 (2862) 3717 (1686) compressor (*) Pump 35 2998(2237) 14120 (6405)  Exchanger 52 .623 (0.157) Exchanger 54 1.01 (0.255)Exchanger 7 2.26 (0.570) Exchanger 37 8.32 (2.10)  Feed Chiller 5.90(1.49)  (*) Refrigeration compressor is not shown in FIG. 2

In this improved process, the flash vessels are all held at constantpressure. The rate of flash gas routed back to the absorber bottomsstage is now adjusted by control valves 62 and 47. If the nitrogencontent of a feed gas were to increase over time, starting with a lowamount of nitrogen, the desired purity of the hydrocarbon product wouldbe maintained by increasing the amount of flash gas routed to theabsorber bottoms stage by initially increasing the amount of gas flowingthrough valve 62 until all of the gas from the first constant pressureflash is routed to the absorber, and none is left to flow to thehydrocarbon product stream. As the inlet nitrogen content increasedmore, valve 47 would be used to increase the flow of flash gas to theabsorber as required. This use of flow control allows for continuousadjustment of flash gas across a very large range without having anyaffect on the pressure of the flash vessels or on the compression ratioof the flash gas compressors. This is made possible by use of dedicatedcompressor 44, in addition to the flash vapor control valves 62, 65, 47and 50. In the conventional design, the service of compressor 44 wasincluded in compressor 32.

This improved process can be used for feed compositions in the range ofthe 24% and 54% compositions as used in the examples for theconventional process. For about 24% nitrogen in the feed, there isminimal flow of first constant pressure flash 13 vapor to thehydrocarbon product through valve 65 with the vast majority being routedthrough valve 62. None of the vapor from the second constant pressureflash flows through valve 47 to the absorber bottoms, and all flowsthrough valve 50 to the hydrocarbon product. With a nearly 54% feed gasnitrogen content, all if the vapor from the first flash would be routedto the absorber, and the vast majority of the vapor from the secondflash would be routed to the absorber bottoms also, with only a minimalamount being routed through valve 50 to the hydrocarbon product.

Performance with close to 54% nitrogen feed case is shown in thefollowing table:

TABLE 6 Flow, lb- Duty, Horsepower moles/hr MMbtu/hr Equipment (KW)(kg-moles/hr) MM kcal/hr) Compressor 32 4367 (3258) 2477 (1124)Compressor 44 1500 (1119) 2038 (924)  Compressor 15 1261 (941)  3656(1658) Refrigeration 4367 (3258) 4229 (1918) compressor Pump 35 3805(2839) 16750 (7598)  Exchanger 52 0.66 (0.17) Exchanger 54 0.98 (0.25)Exchanger 7  3.26 (0.822) Exchanger 37 12.3 (3.07) Feed Chiller  3.91(0.985)

Performance with close to 24% nitrogen feed gas case is shown in thefollowing table:

TABLE 7 Flow, lb- Duty, Horsepower moles/hr MMbtu/hr Equipment (KW)kg-moles/hr) (MM kcal/hr) Compressor 32 4206 (3138) 2246 (1019)Compressor 44 1406 (1049) 1920 (871)  Compressor 15 1264 (943)  3835(1740) Refrigeration 3507 (2616) 3397 (1541) compressor Pump 35 2537(1893) 12440 (9280)  Exchanger 52 0.60 (0.15) Exchanger 54 1.00 (0.25)Exchanger 7  1.42 (0.378) Exchanger 37 4.89 (1.23) Feed Chiller 8.14(2.05)

The following table combines the horsepower of the compressors for thethree feed cases for the present invention provided above, and alsoincluding the results from a case with 12% nitrogen in the inlet gas andmeeting the same light nitrogen stream and hydrocarbon product streamcompositions. For the 12% nitrogen feed case, the vapor from the firstconstant pressure flash is split to the absorber and to the hydrocarbonproduct and all of the vapor from the second flash is routed to thehydrocarbon product:

TABLE 8 Worst Case 12% −24% −37% −54% Load, Each Nitrogen NitrogenNitrogen Nitrogen Equipment HP (KW) HP (KW) HP (KW) HP (KW) HP (KW)Compressor 32 4367 (3258) 3795 (2831) 4206 (3138) 4339 (3237) 4367(3258) Compressor 44 1507 (1124) 1236 (922)  1406 (1049) 1507 (1124)1500 (1119) Compressor 15 1314 (980)  1181 (881)  1264 (943)  1314(980)  1261 (941)  Total 7188 (5362) 6212 (4634) 6876 (5130) 7160 (5341)7128 (5318) Refrigeration 3408 (5242) 3507 (2616) 3837 (2862) 4367(3258) Pump 35 1947 1452) 2537 (1893) 2998 (2237) 3805 (2839)

The performance presented in Table 8 shows a remarkable consistency inthe compressor loads for the gas recompression and recycle to theabsorber services, compressors 32, 44 and 15. The worst case of eachservice totals only 7188 horsepower (5362 KW). Using the conventional(comparative) technology the worst case total was 10,387 horsepower(7749 KW) installed for gas compression, an increase of 44% above thepresent invention. The highest operating horsepower for any case wasalso much higher using the conventional technology, 9,382 (6999 KW)compared to 7,160 (5341 KW) with the present invention, a 31% increase.Compressors 32, 44 and 15 are nearly completely utilized in all cases.Heat exchangers 52 and 54, recovering energy from the flash vesselvapor, are also extremely consistent in the amount of energy recoveredin all cases when used with the present invention. These benefits are inaddition to the original goal of increasing operability by holding thepressure in the flash vessels constant, made possible by using flowcontrol of flash gas vapor recycle to the absorber bottoms rater thanvarying the pressure.

The variation in equipment requirements would be far greater if thedesign did not use this invention; specifically, if it did not offer aflash vessel with a dedicated compressor for the flash vapor, withcapability to route this vapor to the bottom of the absorber, thehydrocarbon product stream, or part of the stream both. Control anddesign is also greatly aided by holding operating pressures constant inthe facility regardless of feed composition.

The disclosed invention is useful for nitrogen rejection fromhydrocarbon streams and also to purify hydrogen contaminated withhydrocarbons, although it is not limited to these applications and maybe used for separation of one or more higher volatility components fromone or more lower volatility components. The solvent used may be made upof heavier components in the feed gas, made of external components addedto the system, or a combination of both. The stripping gas to the bottomof the absorber may be augmented by recycle of a portion of thehydrocarbon product gas, or by adding heat to a reboiler at the bottomof the absorber. Additional exchangers for heat integration may beincluded, such as at the suction of first and second flash vaporcompressors. Additional systems may be added to this invention tostabilize the excess solvent, to further purify the light componentproduct by additional expansion, heat exchange, adsorption, or membraneprocessing, or to recover additional hydrocarbon liquid product byadditional chilling, absorption, or expansion of the product hydrocarbonstream, and the recovered liquid may be used as a separate product or asa means of maintaining solvent inventory. Control systems may be anycombination of level, pressure and flow, including multivariable controlto best maintain a stable operation that can accommodate changes in feedflow, composition, or pressure, along with any desired changes in thefacility operating parameters. The first constant reduced pressure flashvessel compressed vapor may be controlled with flow control on thestream to the absorber bottoms, adjusted to ensure the hydrocarbonproduct does not contain too much of the light component. If there isadditional flow available from the first flash, it would be routed tothe hydrocarbon product by the first flash pressure control valve, 65.When all of the first flash vapor is routed to the absorber and none tothe hydrocarbon product, the pressure in the first flash could then bemaintained by using the pressure control to control valve 62 to theabsorber as valve 65 would be closed and pressure control is required.Obviously there are many choices for the combination of flow control andpressure control, including controls of the compressor and not usingvalves. There are similar choices for control of the vapor from thesecond flash vessel. Although the disclosed invention examples userefrigerant chilling of the feed gas and the solvent to −25° F. (−31.7°C.), this temperature may vary according to the application, withtemperatures from as warm as +20° F. (−6.7° C.) and as cold as −40° F.(−40° C.) foreseen with refrigeration, even colder temperatures ifexpansion of the feed gas is utilized, or as high as ambient temperatureis refrigeration is not utilized.

All of the methods and apparatus disclosed herein can be made andexecuted without undue experimentation in light of the presentdisclosure. While the methods of this invention have been described interms of specific embodiments, it will be apparent to those of skill inthe art that variations may be applied to the methods and apparatus andin the steps or in the sequence of steps of the methods described hereinwithout departing from the concept, spirit and scope of the invention.All such similar substitutes and modifications apparent to those skilledin the art are deemed to be within the spirit, scope, and concept of theinvention as defined by the following claims.

What is claimed is:
 1. A process for separating the components of avariable composition multi-component gas stream comprising lightcomponents and heavier hydrocarbon components, the process comprising:contacting the multi-component gas stream with a lean solvent in anabsorber to produce a light component overhead stream and a rich solventbottoms stream; directing the rich solvent bottoms stream to a firstflash vessel at a first constant reduced pressure to produce a vapor ofwhich all or part of the vapor is routed to the absorber bottom stageand with the remaining vapor routed to the produced hydrocarbon productstream; directing the rich solvent from the first flash vessel to asecond flash vessel at a further reduced second constant pressure toproduce a vapor; directing the rich solvent from the second flash vesselto one or more reduced pressure flash vessels with the producedhydrocarbon vapor compressed and routed to the produced hydrocarbonstream; and recycling the regenerated lean solvent from the last, lowestpressure flash vessel through a pump to the absorber.
 2. Then process ofclaim 1, wherein all of the produced vapor from the first flash vesselis routed to the absorber bottoms stage and a part of the produced vaporfrom the second flash vessel is routed to the absorber bottom stage. 3.The process of claim 1, wherein a part of the produced vapor from thefirst flash vessel is routed to the absorber bottoms stage and none ofthe produced vapor from the second flash vessel is routed to theabsorber bottom stage.
 4. The process of claim 1, wherein the absorberis operated at a pressure between 200 psia and 3000 psia (13.8 and 207bara).
 5. The process of claim 1, wherein the flash vessels are operatedat a pressure between 2800 psia and 7 psia (193 and 0.48 bara) with eachsuccessive vessel operating at a pressure lower than the precedingvessel.
 6. The process of claim 5, wherein the pressure in eachsuccessive flash vessel is about 20 to 75% of the pressure in thepreceding vessel.
 7. The process of claim 1, wherein the process isoperated at a temperature between ambient temperature and 20° F. (−6.7°C.).
 8. The process of claim 1, wherein process streams are cooled andthe absorber is operated at a temperature between +20° F. and 40° F.(−6.7 and 40° C.).
 9. The process of claim 1, wherein one or morecontrol valves are used to adjust the vapor rate routed to the bottomstage of the absorber.
 10. The process of claim 1, wherein a compressorused to route the vapor from the first flash vessel to the absorberbottoms stage is the same compressor used for routing the vapor fromfirst flash vessel to the hydrocarbon product.
 11. The process of claim1, wherein a pressure control of the first flash vessel is used todirect the produced vapor to the hydrocarbon product.
 12. The process ofclaim 1, wherein the vapor from the first pressure flash vessel iscompressed by a compressor dedicated to this service.
 13. The process ofclaim 1, wherein the vapor from the second flash vessel is compressed bya compressor dedicated to this service.
 14. The process of claim 1,wherein at least portion of the vapor from the second flash vessel isrouted to the produced hydrocarbon product stream.
 15. The process ofclaim 1, wherein the vapor from the second flash vessel is routed to theproduced hydrocarbon product stream.
 16. The process of claim 1, whereinat least portion of the vapor from the second flash vessel is routed tothe absorber bottom stage.
 17. The process of claim 1, wherein all,none, or part of the vapor from the second flash vessel is routed to thehydrocarbon product stream with the remaining vapor from the secondflash vessel routed to the absorber bottom stage.
 18. The process ofclaim 1, wherein all, none, or part of the vapor from the second flashvessel is routed the absorber bottom stage with the remaining vapor fromthe second flash vessel routed to the produced hydrocarbon productstream.
 19. The process of claim 1, wherein a control valve is used toadjust the vapor rate routed to the hydrocarbon product stream.
 20. Theprocess of claim 1, cooling the recycled the regenerated lean solventfrom the last, lowest pressure flash vessel with a propane chiller priorto reaching the absorber.